The present disclosure relates generally to a system for communicating about a wellsite with, for example, subsurface components. More specifically, the disclosure relates to bi-directional communication systems for use with wellsite equipment, such as surface and/or downhole networks and tools.
Oilfield operations are typically performed to locate and gather valuable downhole fluids. Oil rigs are positioned at wellsites, and downhole tools, such as drilling tools, are deployed into the ground to reach subsurface reservoirs. During such oilfield operations it may be necessary to communicate about the wellsite with, for example, surface, downhole and/or offsite tools and/or equipment. Such communications may be used, for example, to collect downhole data and/or to send commands to control the operation of downhole tools.
Today's wells are often characterized by their increased reservoir contact. This may be achieved by drilling longer step-out wells. The expansion of the extended reach drilling practice alone may push the envelope of the technologies typically deployed. As more complex oilfield operations are employed, communication about wellsites is becoming increasingly important and increasingly complex. Moreover, wellsites have limited bandwidth and limited data rates for transmitting signals about the wellsite. Typical data transmission rates with mud pulse telemetry, for example, may range from about 20 bytes per second (bps) in shallow wellbore sections to about a few bps for a deep well. With the mud pulse signal degrading at extreme depths, engineers are often limited to only a few survey data points for placing their extended reach wellbores. The limited data transmission from downhole tools may not only limit the clarity of the subsurface, but also the mechanical aspects of drilling may remain unknown for adequate decision making.
As drilling operations become more challenging, geologists, operators and engineers need new ways to improve operational efficiency, increase production, reduce NPT and minimize risks. Networked drill pipe is a recent technology transforming current standards for drilling, and has the potential to unlock wells that are un-drillable with current technologies. Such networked or wired drill pipe may be used to provide communication between surface and downhole oilfield operations at the wellsite.
Wired pipe telemetry systems using a combination of electrical and magnetic principles to transmit data between a downhole location and the surface are described in, for example, U.S. Pat. Nos. 6,670,880, 6,641,434 and 7,198,118 (all are hereby entirely incorporated herein by reference). In these systems, inductive transducers are provided at the ends of wired pipes. The inductive transducers at the ends of each wired pipe are electrically connected by an electrical conductor running along the length of the pipe. Data transmission involves transmitting an electrical signal through an electrical conductor in a first wired pipe, converting the electrical signal to a magnetic field upon leaving the first wired pipe using an inductive transducer at an end of the first wired pipe, and converting the magnetic field back into an electrical signal upon entering a second wired pipe using an inductive transducer at an end of the second wired pipe. Multiple wired pipes are typically needed for data transmission between the downhole location and the surface.
Wired drill pipe has the capability to transmit data at a high rate (e.g., 57,000 bits per second). Thus, the wired drill pipe may be used to make downhole information available in real time. The vast increase in data volume at higher quality unlocks the potential for better decisions and further improves drilling performance. The very high data telemetry rates also provide full control over downhole tools, such as rotary steerable tool settings while drilling.
The high-speed, high-volume, high-definition, bi-directional broadband data transmission enables downhole conditions to be measured, evaluated, and monitored, allowing tool actuation and control in real time.
The oil rig has a top drive connected to an upper most of a number of wired drill pipe that form a drill string that extends from the surface to the downhole tool. The top drive may include a rotary connector, or top drive coupler, for linking the wired drill pipe to surface systems, thereby allowing for communication with the downhole tool(s) during drilling. However, many operational problems may occur in extended reach wells while the wired drill pipe is not coupled to the top drive. For example, the top drive is typically not coupled to the wired drill pipe while tripping. Tripping is defined as the set of operations associated with removing or replacing an entire string or a portion thereof from/into the borehole. Getting stuck is a frequent occurrence during tripping. Mud pulse telemetry—with its reliance on fluid flow—doesn't provide downhole measurements while tripping.
During such ‘tripping,’ the rotary connector is disconnected from the drill string, resulting in a loss of communication between the surface equipment and the drill string. It is typically desirable for the drilling crew to have access to the downhole information while tripping. Tripping may be necessary for a number of well operations involving a change to the configuration of the bottom-hole assembly, such as replacing the bit, adding a mud motor, or adding measurement while drilling (MWD) or logging while drilling (LWD) tools. Tripping can take many hours, depending on the depth to which drilling has progressed. The ability to maintain communication with downhole tools and instruments during tripping can enable a wide variety of MWD and LWD measurements to be performed during time that otherwise would be wasted. This ability may also enhance safety. For instance, in the event that a pocket of high-pressure gas breaks through into the wellbore, the crew may be given critical advance warning of a dangerous “kick,” and timely action can be taken to protect the crew and to save the well. Maintaining communication during tripping may also give timely warning of lost circulation or of other potential problems, thereby enabling timely corrective action.
With a broadband network that is always on regardless of flow, drillers may have an insight into the dynamic downhole hydrostatic pressure with real-time measurements while tripping. These measurements may accurately reveal the dynamic surge and swap pressures, instead of relying on conservative rules of thumb or on mathematical models for determining safe operating ranges for the trip speed. Excessive surge pressure could result in time-consuming lost circulation events, while excessive swap pressure could lead to dangerous and costly well control events. With the broadband network integrating the downhole measurements with the surface equipment, a truly closed loop feedback system may be provided. Downhole measurements (e.g., pressure) can set the optimum tripping speed by controlling the speed of the drawworks system.
Connection to the downhole network at surface can be established in various ways. U.S. Pat. No. 7,198,118 describes a screw-in communication adapter that provides for removable attachment to a drilling component when the drilling component is not actively drilling, and for communication with an integrated transmission system in the drilling component. The communication adapter includes a data transmission coupler that facilitates communication between the drill string and the adapter, a mechanical coupler that facilitates removable attachment of the adapter to the drill string, and a data interface.
Despite the advancements in wellsite communications, there remains a need to provide techniques for maintaining communication during oilfield operations. It is desirable that such techniques enable communication during interruptions, such as tripping. It is further desirable that such techniques permit mudflow into the tool such interruptions. Preferably, such techniques provide one or more of the following, among others: reduced communication interruption, increased communication during tripping, reduced manning during tripping, improved and/or repeat downhole measurement (e.g., hydrostatic pressure, drill string strain, inclination, azimuth) while tripping, reduced operational downtime during tripping (and/or prevention of stuck pipe), the acquisition of real time distributed downhole measurements and/or drill string dynamic analysis while tripping, and/or manual and/or automated adjustment of downhole tools while tripping, allow for downhole fluid power generation while tripping, control of swab pressure, and control of bottom hole pressure.